Hydrogen storage method and system

ABSTRACT

A method and system for storing and supplying hydrogen to a hydrogen pipeline in which a compressed hydrogen feed stream is introduced into a salt cavern for storage and a stored hydrogen stream is retrieved from the salt cavern and reintroduced into the hydrogen pipeline. A minimum quantity of stored hydrogen is maintained in the salt cavern to produce a stagnant layer having a carbon dioxide content along the cavern wall and the top of a residual brine layer located within the salt cavern. The compressed hydrogen feed stream is introduced into the salt cavern and the stored hydrogen stream is withdrawn without disturbing the stagnant layer to prevent carbon dioxide contamination from being drawn into the stored hydrogen stream being reintroduced into the hydrogen pipeline. This allows the stored hydrogen stream to be reintroduced into the hydrogen pipeline without carbon dioxide removal.

FIELD OF THE INVENTION

The present invention relates to a hydrogen storage method and system inwhich hydrogen is stored in a salt cavern and introduced from the saltcavern into a hydrogen pipeline without removal of carbon dioxide.

BACKGROUND OF THE INVENTION

Hydrogen is utilized in a variety of industrial processes and istypically produced from the steam methane reforming of hydrocarbons thatare contained in natural gas. The hydrogen after production can be usedon site where the steam methane reformer is located or can bedistributed to customers with the use of a pipeline.

Customer demand will typically vary and it has been found to beadvantageous to store the hydrogen when customer demand is low for lateruse during peak demand periods. One central advantage in storing thehydrogen is that the hydrogen production facility does not have to besized to meet peak customer demands and thus, can be a smaller, lowercost installation. Additionally, the storage of hydrogen also allows forfurther profitability in that spot sales of hydrogen can be made tocustomers, above that required to meet contractual customer demands.Since the storage requirements related to pipeline distribution systemscan be at a level of over a billion standard cubic feet of hydrogen,large underground geological formations known as salt caverns are usedfor such purposes.

Salt caverns are formed by solution mining within large undergroundformations of salt that can be several hundred to several thousands offeet deep that are generally covered by a cap rock. In order to form thesalt cavern, a well is drilled from the surface down to and through thesalt formation. The well hole is supported by pipe casings which aresurrounded by concrete and a smaller pipe, known as a brine string, isinserted into the casing to introduce water down into the hole. Thewater dissolves the salt to form the cavern and the resulting brine ispumped to the surface between the annular space formed between thecasing and the smaller pipe. Additionally, brine is removed from thecavern by injecting hydrogen to pressurize the cavern and force thebrine out through the brine string. When complete, the salt cavern has aroof region at the top of the salt cavern and beneath the cap rock, sideregions connecting the roof regions with the bottom of the salt cavernand a residual brine layer or brine sump remaining at the bottom of thesalt cavern.

The hydrogen to be stored can be produced at the site of the salt cavernor can be removed from the pipeline itself. The hydrogen is compressedby a compressor and the resulting compressed hydrogen feed stream isintroduced into the salt cavern through the casing. When the hydrogenrequired to meet customer demand is greater than that able to beproduced by the hydrogen production facility, the hydrogen is taken fromthe salt cavern as a stored hydrogen stream through the casings andinjected back into the pipeline.

Carbon dioxide as well as other impurities can be introduced into thestored hydrogen stream from the salt cavern itself. The carbon dioxideimpurity, as well as moisture, for the most part, evolves from theresidual brine layer. Since the pipeline itself will have aspecification for the amount of carbon dioxide and also, possiblymoisture, that can be contained in the hydrogen that is reintroducedinto the pipeline, the carbon dioxide impurity that is introduced intothe stored hydrogen stream is removed by an adsorption unit thatcontains an adsorbent to adsorb the carbon dioxide and also possibly themoisture. For example, in U.S. Pat. No. 7,078,011, a purification systemis used in connection with the salt cavern to reduce levels of carbondioxide and moisture to sufficiently low levels that are necessary tomeet the pipeline specification. It has been found that the use ofcarbon dioxide purification system adds a level of complexity andexpense to the operation of an installation that involves the storage ofhydrogen within a salt cavern. As will be discussed, it has been foundthat although unacceptably high levels of carbon dioxide can initiallybe imparted from the salt cavern to the stored hydrogen stream to beinjected back into the pipeline, when the salt cavern is operated in amanner as described in the present invention, carbon dioxide removalwill not be necessary.

SUMMARY OF THE INVENTION

The present invention provides, in one aspect, a method of storing andsupplying hydrogen to a hydrogen pipeline. In accordance with themethod, a feed stream of the hydrogen is compressed to produce acompressed hydrogen feed stream. The compressed hydrogen feed stream isinjected into a salt cavern, through at least one conduit, to producestored hydrogen within the salt cavern and a stored hydrogen stream,composed of the stored hydrogen, is withdrawn from the salt cavernthrough the at least one conduit. The salt cavern has a residual brinelayer located at a bottom region of the salt cavern and side regionsextending upwardly from the bottom region of the salt cavern and the atleast one conduit has at least one lower end located in an interiorregion of the salt cavern and spaced above the brine layer and from theside regions of the salt cavern. The stored hydrogen stream isintroduced into the hydrogen pipeline, after having been withdrawn fromthe salt cavern, without removing carbon dioxide present within thestored hydrogen stream.

The compressed hydrogen feed stream is injected into the salt cavern andthe stored hydrogen stream is withdrawn from the salt cavern through atleast one conduit having at least one lower end located in an interiorregion of the salt cavern and spaced above the brine layer and from theside regions of the salt cavern. At least a minimum quantity of thestored hydrogen is maintained within the salt cavern before, during, andbetween times at which the compressed hydrogen feed stream is injectedand at which the stored hydrogen stream is withdrawn such that astagnant layer of hydrogen is maintained that borders the interiorregion and has at least a bottom portion overlying the residual brinelayer and a lateral portion situated along the side regions of the saltcavern. The stagnant layer has a carbon dioxide content that is apotential source of carbon dioxide contamination to the stored hydrogenstream. The flow rates and the velocities at which the compressedhydrogen feed stream is injected into the salt cavern and the storedhydrogen stream is withdrawn the salt cavern are limited such that thestagnant layer is not disturbed and the carbon dioxide contamination ofthe stored hydrogen stream from the stagnant layer is inhibited.

As a result, for the most part, any carbon dioxide contained in thestored hydrogen stream is a result of the carbon dioxide contained inthe salt cavern. However, any such carbon dioxide contamination is at anextremely low level given that it will arise from molecular diffusion ofthe hydrogen from the stagnant layer to the interior region and suchtransport of hydrogen is an extremely slow process. As such, carbondioxide removal is not necessary.

The at least one lower end of the at least one conduit can be spacedbelow a top region of the salt cavern, located opposite to the bottomregion of the salt cavern. In such case, the stagnant layer also has atop portion extending along the top region of the salt cavern andsituated opposite to the bottom portion of the stagnant layer. Water canbe removed from the stored hydrogen stream prior to injection into thepipeline. Further, the hydrogen feed stream can be compressed to apressure above the pipeline pressure within the pipeline and as aresult, the stored hydrogen has a cavern pressure that is above thepipeline pressure. The stored hydrogen stream can therefore be removedfrom the salt cavern as a consequence of the cavern pressure and thestored hydrogen stream is reduced to the pipeline pressure prior toinjecting the stored hydrogen stream into the pipeline.

In another aspect of the present invention, a system is provided forstoring and supplying hydrogen to a hydrogen pipeline. A compressor isprovided for compressing a feed stream of the hydrogen to produce acompressed hydrogen feed stream. A salt cavern is incorporated into thesystem and has a residual brine layer located at a bottom region of thesalt cavern and side regions extending upwardly from the bottom regionof the salt cavern. At least one conduit is in communication with thesalt cavern for injecting the compressed hydrogen feed stream into asalt cavern to produce stored hydrogen within the salt cavern and forwithdrawing a stored hydrogen stream composed of stored hydrogen fromthe salt cavern. The at least one conduit has at least one lower endlocated in an interior region of the salt cavern and spaced above thebrine layer and from the side regions of the salt cavern. A flow networkis configured to selectively connect the compressor to the at least oneconduit such that the compressed hydrogen feed stream is injected intothe salt cavern to produce the stored hydrogen within the salt cavernand to selectively connect the at least one conduit to the hydrogenpipeline such that the stored hydrogen stream is injected into thepipeline without removing carbon dioxide contained in the storedhydrogen stream.

The salt cavern has at least a minimum quantity of the stored hydrogenwithin the salt cavern before, during, and between times at which thecompressed hydrogen feed stream is injected and at which the storedhydrogen stream is withdrawn such that a stagnant layer of hydrogen ismaintained that has at least a bottom portion overlying the residualbrine layer and a lateral portion situated along side regions of thesalt cavern. The stagnant layer has a carbon dioxide content that is apotential source of carbon dioxide contamination to the stored hydrogenstream. A means is provided for limiting the flow rates and thevelocities at which the compressed hydrogen feed stream is injected intothe salt cavern and the stored hydrogen stream is withdrawn from thesalt cavern such that the stagnant layer is not disturbed and the carbondioxide contamination of the stored hydrogen stream from the stagnantlayer is inhibited.

The at least one lower end of the at least one conduit can be spacedbelow a top region of the salt cavern, located opposite to the bottomregion of the salt cavern. In such case, the stagnant layer also has atop portion extending along the top region of the salt cavern andsituated opposite to the bottom portion of the stagnant layer. The flownetwork can be provided with a drying unit positioned within the flownetwork to remove water from the stored hydrogen stream prior toinjection into the pipeline. The compressor compresses the hydrogen feedstream such that the compressed hydrogen feed stream is injected intothe salt cavern at a cavern pressure that is above the pipelinepressure. The flow network is configured to reduce the pressure of thestored hydrogen stream to the pipeline pressure prior to injecting thestored hydrogen stream into the pipeline.

In either aspect of the present invention, the at least one conduit canhave an injection conduit and a withdrawal conduit. The compressedhydrogen feed stream is injected into the salt cavern through theinjection conduit and the stored hydrogen stream is withdrawn from thesalt cavern through the withdrawal conduit. The at least one conduit canalso comprise an injection conduit having a flow diffuser from which atleast the compressed hydrogen feed stream is injected into the saltcavern.

Furthermore, in either aspect of the present invention, the minimumvolume of the hydrogen stored within the salt cavern can be maintainedat a volume ratio equal to a stored volume of the hydrogen to the actualcavern volume of no less than 29.0 scf/cf. It is to be noted here that,as used herein and in the claims, the unit “scf/cf” means standard cubicfeet of the stored hydrogen per actual cubic feet of the cavern volumeable to contain the stored hydrogen. The actual cubic feet of cavernvolume able to contain the stored hydrogen is computed by subtractingthe volume of the residual brine layer from the total volume of the saltcavern. In case the at least one lower end of the at least one conduitis open, rather than incorporating a flow diffuser, the at least onelower end of the at least one conduit can be spaced from the residualbrine layer at a lower vertical distance of no less than 250 feet and isalso spaced from the side regions of the salt cavern at a lateraldistance of no less than 40 feet as measured from a vertical lineextending between 10 and 250 feet below the at least one lower end ofthe at least one conduit. The flow rates and velocities are limited suchthat, as measured at the at least one lower end of the at least oneconduit, the compressed hydrogen feed stream is injected at an injectionratio equal to an injection flow rate of the compressed hydrogen feedstream to the actual cavern volume of no greater than 7.5 scfd/cf and atan injection velocity of the compressed hydrogen feed stream of nogreater than 100 feet per second and the stored hydrogen stream iswithdrawn at a withdrawal ratio equal to the withdrawal flow rate of thestored hydrogen stream to the actual cavern volume of no greater than10.0 scfd/cf and at a withdrawal velocity of the stored hydrogen streamof no greater than 150 feet per second. It is to be mentioned that, asused herein and in the claims, the unit “scfd/cf” means the flow ratemeasured in standard cubic feet per day per cubic feet of the actualcavern volume that is able to store the stored hydrogen.

Where the at least one lower end of the at least one conduit is spacedbelow a top region of the salt cavern, the at least one lower end can bespaced from the top region of the salt cavern at an upper verticaldistance of no less than 50 feet.

In the aspect of the present invention relating to the method, where thehydrogen feed stream contains less than 1.0 ppmv carbon dioxide and lessthan 8 ppmv carbon monoxide, a sum of a carbon dioxide content andcarbon monoxide content in the stored hydrogen stream is to be less than10 ppmv. Where hydrogen feed stream contains less than 0.1 ppmv carbondioxide and less than 0.6 ppmv carbon monoxide, a sum of a carbondioxide content and carbon monoxide content in the stored hydrogenstream is less than 1.0 ppmv. The unit “ppmv” as used herein and in theclaims means parts per million by volume on a dry basis or in otherwords without considering the water content.

BRIEF DESCRIPTION OF THE DRAWINGS

While the specification concludes with claims distinctly pointing outthe subject matter that Applicants regard as their invention, it isbelieved that the invention will be better understood when taken inconnection with the accompanying drawings in which:

FIG. 1 is a fragmentary, schematic illustration of a system for storingand supplying hydrogen to a hydrogen pipeline that carries out a methodin accordance with the present invention;

FIG. 2 is a fragmentary, schematic illustration of the system of FIG. 1showing further details of the salt cavern that is used in connectionwith the system; and

FIG. 3 is a fragmentary, schematic illustration of an alternativeembodiment of FIG. 1 showing alternative injection and withdrawalconduits.

DETAILED DESCRIPTION

With reference to FIG. 1 a system 1 is illustrated for storing andsupplying hydrogen to a hydrogen pipeline 2. Hydrogen traverses thehydrogen pipeline 2 in a direction taken from point “A” to point “B”,from a facility used in generating the hydrogen to customers consumingthe hydrogen. The hydrogen generation facility can employ a steammethane reformer to reform a hydrocarbon containing stream into ahydrogen and carbon monoxide containing stream. Such facility typicallyalso uses one or more stages of water-gas shift to react the carbonmonoxide with steam and generate additional hydrogen and a hydrogenpressure swing adsorption unit to purify the resulting shifted streamand thereby generate the hydrogen product.

Briefly, the present invention contemplates drawing off a hydrogen feedstream from the hydrogen pipeline 2 during periods of low customerdemand and then compressing the hydrogen within a compression side 3 aof a flow network 3 to produce a compressed hydrogen feed stream that isinjected into salt cavern 4 through a final well casing 28. Thecompressed hydrogen feed stream is illustrated by arrowhead “C”. Duringperiods of high demand or when additional hydrogen can be sold, thehydrogen previously stored in the salt cavern 4, as stored hydrogen, isreintroduced into final well casing 28 as a stored hydrogen stream thatis illustrated by arrowhead “D”. The stored hydrogen stream, afterpassage through return side 3 b of flow network 3 is reintroduced intohydrogen pipeline 2.

It has been found by the inventors herein that suitable control of theinjection, storage and removal of the hydrogen within the salt cavern 4by the flow network 3 allows the hydrogen to be removed from the saltcavern 4 without having to remove carbon dioxide. In this regard, it hasbeen found that by maintaining a minimum volume of hydrogen within thesalt cavern 4, a stagnant layer of hydrogen will be produced thatcontains carbon dioxide contamination that could be introduced into thestored hydrogen stream to be reintroduced back to the pipeline 2. Aswill be discussed, the stagnant layer has bottom and lateral portions124 and 122 and also possibly a top portion 126 that are all shown inFIG. 2. Limiting flow rates and velocities of both the compressedhydrogen feed stream and the stored hydrogen stream will preventdisturbance of such stagnant layer to thereby inhibit the carbon dioxidecontamination from being drawn into the stored hydrogen stream.

With specific reference to FIG. 1, a hydrogen feed stream is withdrawnfrom the hydrogen pipeline 2 through a conduit 10 when it is desired tostore hydrogen within salt cavern 4. It is understood, however, that thehydrogen production facility could be located at the site of the saltcavern 4 and in such case, the hydrogen feed stream could be separatelyproduced on site without withdrawal from the hydrogen pipeline 2 or by acombination of withdrawal from the hydrogen pipeline 2 and on-sitehydrogen production.

Within the compression side 3 a of flow network 3, a valve 12 is set inthe open position for purposes of feeding the hydrogen feed stream fromthe hydrogen pipeline 2 to the salt cavern 4. The hydrogen feed streamis then introduced into a hydrogen compressor 14. Upstream of thehydrogen compressor 14 is a pressure transducer 16 connected to apressure controller 18 by an electrical connection 17. In response tothe pressure sensed by pressure transducer 16, controller 18 operates aproportional control valve 20 by means of an electrical connection 21.The pressure controller 18 is programmed to operate control valve 20such that the inlet pressure of the hydrogen feed stream to thecompressor 14 is maintained at a target pressure. The target pressure isset to ensure that the inlet conditions are consistent with design ofcompressor 14.

Although not illustrated, further instrumentation could be provided atthe inlet of the compressor 14 to measure flow, pressure and temperatureof the hydrogen feed stream. The flow would be measured by an orificemeter and the measurement is then corrected by the measured pressure andtemperature to determine the flow of the hydrogen feed stream from thehydrogen pipeline 2 for purposes of monitoring the quantity of hydrogenremoved from the pipeline and for providing a basis for assessing theintegrity of the compression system, for instance, detecting leaks.

The resulting compressed hydrogen feed stream flows through a controlvalve 22 and a valve 24 that is set in an open position during injectionof hydrogen into salt cavern 4. The compressed hydrogen feed stream thenflows through transfer line 26 and into an annular space 29 within finalwell casing 28 from which the compressed hydrogen feed stream enterssalt cavern 4. A well head valve 30 connects the final well casing 28 tothe transfer line 26. Such valve is left in a normally open position.

As mentioned above, in order to allow the stored hydrogen stream to beintroduced into hydrogen pipeline 2 without disturbing the stagnantlayer and therefore, without removal of carbon dioxide from the storedhydrogen stream, it is important to limit the flow rate and velocity ofthe compressed hydrogen feed stream into the salt cavern 4. The flowrate and velocity of the compressed hydrogen feed stream can be limitedby selecting a compressor capacity for compressor 14. The flow rate ofthe compressed hydrogen stream will be limited by such capacity. Since,the annular flow area provided in final well casing 28 (between theinside of final well casing 28 and a pipe 110 known as a brine string)is a known quantity, the limitation of flow rate produced by thecompressor 14 will result in the compressed hydrogen feed stream neverreaching the limiting velocity that would disturb the stagnant layer.The limiting velocity is calculated by dividing the flow limiting rateof the compressed hydrogen feed stream produced by compressor 14 inactual cubic feet divided by the annular flow area of the final wellcasing 28. The “actual cubic feet” of the hydrogen is computed at apressure that would constitute the lowest operating pressure of the saltcavern 4 and the temperature of the compressed hydrogen feed streamleaving the compressor 14 after the after-cooler. Other moresophisticated electronic control systems are also possible.

Within the limit of maximum flow, limited in a manner set forth above,the flow rate of the hydrogen feed stream being withdrawn from hydrogenpipeline 2 must be controlled to control the amount of hydrogen that maybe removed from hydrogen pipeline 2 while still allowing the hydrogenpipeline 2 to deliver sufficient hydrogen to meet customer demand. Forsuch purposes, a control valve 22 is provided that is controlled by acontroller 32 through a connection 34 and also, controls, to bediscussed, that are associated with the compressor 14. Control valve 22controls the flow by setting the back-pressure to the compressor 14.Controller 32 is a programmable unit that responds to flow measured byan orifice meter 36 through an electrical connection 38. The measuredflow is corrected by actual pressure and temperature measurements thatare obtained by a pressure transducer 40 and a temperature transducer 42that are connected to the controller 32 by means of electricalconnections 44 and 46, respectively.

Compressor 14 is a reciprocating machine that is sized, as mentionedabove, such that the capacity of the machine is less than the maximumallowable flow rate of the compressed hydrogen feed stream to the saltcavern 4. If two or more stages were used in compressor 14, intercoolerswould be provided. Although not illustrated, the compressed hydrogenfeed stream will typically be cooled by an after-cooler. When sufficientextra hydrogen is available, the salt cavern 4 will be filled at ratesconsistent with the maximum capacity of the compressor 14. If less extrahydrogen is available from the hydrogen pipeline 2, controller 30controls control valve 22 to reduce the flow rate of the compressedhydrogen feed stream.

Since reciprocating compressors displace a constant volume of gasregardless of operating conditions, the compressor 14 is generallyconfigured to displace somewhat more gas than is required. Although notillustrated, but as would be well known in the art, compressor 14 isprovided with its own flow control system that is connected to acontroller 48 by electrical connections generally shown by referencenumber 50. As discussed above, such control acts in concert with thecontrol of proportional control valve 22 to control the flow of thecompressed hydrogen feed stream being injected into the salt cavern 4.Part of such control system associated with the compressor can include aby-pass line. When more volume is compressed than is required, theexcess gas may then be sent back to the suction side of the compressor14 through the bypass line. Another alternative is to simply vent theexcess gas that could be flared. Thus, when control valve 22 closes toreduce the flow rate of the compressed hydrogen feed stream, controller48 would act to open a valve and route the excess gas back to thesuction side of the compressor 14 through the by-pass line. In suchmanner the flow rate hydrogen feed stream being withdrawn from thehydrogen pipeline 2 can be controlled. Alternatively, the controller 48could be programmed to control the speed of the motor driving compressor14 to trim the quantity of gas displaced. This is not a typicalarrangement since most reciprocating compressors are designed to run ata constant speed. Another mechanism that is often used is to vary theamount of gas that the compressor displaces. This mechanism iseffectuated through loading and unloading the compressor. There are twomethods of loading and unloading a reciprocating compressor. The firstmethod involves holding the intake valves associated with compressor 14in an open position. This method in combination with a by-pass line isthe preferred mode of control when double acting hydrogen compressorsare used. In such method, the controller 48 would act on the intakevalves to the compressor 14. The second method involves small pockets orreservoirs that are typically associated with a compressor such ascompressor 14 which are opened by valves when unloading the compressor.The gas is compressed into these pockets on the compression stroke andexpanded on the return stroke, thereby preventing the compression of anyadditional gas. Compressors can have multiple clearance pockets per eachstage. For example, if four clearance pockets are provided per stagethen a five-step flow control can be achieved, namely, full load,three-quarters load, one-half load, one-quarter load and no load. Whentwo stages or more stages are used each stage should be equally loadedto maintain a relatively consistent compression ratio for each stage. Ifthe stages are not equally loaded, then the pressure between the twostages will be either too high or too low and this might result indamage to the compressor 14. In case of such control, the controller 48would act on valves that would be set in open positions to allow flowinto the clearance pockets to in turn control flow of the compressedhydrogen feed stream.

It is to be noted that the compressed hydrogen feed stream is normallycompressed to a pressure that is above the pipeline pressure of hydrogenflowing within hydrogen pipeline 2 and as such, the resulting storedhydrogen within salt cavern 4 is at a cavern pressure that is above thepipeline pressure of the hydrogen pipeline 2. The maximum pressure andthe minimum pressure, as measured by a pressure transducer 52 withintransfer line 26, are set such that the structural integrity of the saltcavern 4 is not compromised. In a manner that will be discussed, thepressure measured by pressure transducer 52 is used in the control ofcompressor 14. The maximum pressure is set to keep the cavern pressurebelow the pressure defined by the lithostatic head to prevent fracturingand the minimum pressure is set to prevent the salt cavern 4 fromclosing in on the storage volume, often called creep. If a high level ofcreep is allowed the cavern can lose its integrity, and will either losehydrogen when the cavern pressure is raised or when the cavern pressureis low allow hydrocarbons, carbon dioxide, and other gases that might bepresent in the surrounding structures to enter the cavern andcontaminate the hydrogen or in a worst case, will result in the cavern 4collapsing. As will be discussed, in the present invention, the minimumpressure is also set to assure that a minimum volume of hydrogen isalways stored within the salt cavern 4. A temperature measurement ismade by a temperature transducer 54, also for purposes of assuring theminimum volume of stored hydrogen is maintained.

When withdrawing the stored hydrogen from the salt cavern 4, valves 12and 24 are set in closed positions and valves 56 and 58 are set in openpositions. The stored hydrogen, as a consequence of the cavern pressure,flows as stored hydrogen stream through final well casing 28 andtransfer line 26 back to the hydrogen pipeline 2 through the return side3 b of flow network 3. As mentioned above, the flow rate and thevelocity of the stored hydrogen stream is also limited to preventdisturbance of the stagnant layer and thereby to allow the storedhydrogen stream to be reintroduced into hydrogen pipeline 2 withoutcarbon dioxide removal. This control can be effectuated by appropriatesizing of a proportional control valve 60, to be discussed, throughwhich the stored hydrogen stream flows. The appropriate sizing of suchvalve, in a manner known in the art, will result in the stored hydrogenstream from never being able to exceed a maximum allowable flow rate andflow velocity within the salt cavern 4 that would disrupt the stagnantlayer. The flow velocity would be computed by dividing the limiting flowrate of the stored hydrogen stream in actual cubic feet by the flow areaof the final well casing 28. Here, the “actual cubic” feet would becomputed at the lowest operating pressure of the salt cavern 4 and at atemperature of the stored hydrogen at the lower end 128 of the finalwell casing 28 that is an adjusted produced gas temperature based on thelocal geothermal gradient of the stored hydrogen.

In addition to acting as a flow and velocity limiter for the storedhydrogen stream, the proportional control valve 60 is used in connectionwith a drying unit 62 to make certain that pressure limitationassociated with the drying unit 62 is never exceeded. Proportionalcontrol valve 60 is controlled by a pressure controller 64 through anelectrical connection 65 that reacts to a pressure sensed by a pressuretransducer 66, connected to pressure controller 64 through an electricalconnection 67. This pressure control is designed to insure that thepressure of the stored hydrogen stream being fed into drying unit 62will not exceed the pressure limit of the drying unit 62. Drying unit 62can use an adsorbent system, a liquid glycol dehydration system, orother drying concepts to remove moisture from the stored hydrogenstream. However, this is optional and in fact, such a unit could beplaced on the customer site for such purposes. In fact, if the hydrogenis injected into, stored and withdrawn in accordance with the presentinvention, the moisture content could be sufficiently low as to notrequire moisture removal at any location. This would depend uponpipeline specifications for the hydrogen pipeline 2 and requirements ofthe customer consuming the hydrogen. If drying unit 62 were notemployed, the return side 3 b of the flow network 3 would be designed byprovision of a separate valve coupled with piping pressure losses toproduce a pre-specified pressure drop so that maximum flow rates andvelocities of the stored hydrogen stream would never exceed a maximumallowable flow rate and velocity in connection with the disturbance ofthe stagnant layer within the salt cavern 4.

The resulting dried stored hydrogen stream then passes through aproportional control valve 68 that controls the flow of the storedhydrogen stream for purposes of metering the amount of hydrogen thatwill be redelivered back to the hydrogen pipeline 2. The proportionalcontrol valve 68 is controlled by a controller 70 through an electricalconnection 72. Controller 70 reacts to flow measured by an orifice meter74 that is connected to controller 70 by way of an electrical connection76. The measured flow is corrected within controller 70 throughtemperature and pressure measurements made by pressure and temperaturetransducers 78 and 80 that are connected to the controller 70 byelectrical connections 82 and 84, respectively. The controller 70 is setwith targets in a manner to be discussed that provide the hydrogen flowto the hydrogen pipeline 2 as required to meet the needs of the system 1with respect to down stream customers and potential spot sales.Thereafter, the stored hydrogen stream passes through valve 58 and backinto the hydrogen pipeline 2 through conduit 10.

In the illustrated embodiment, the stored hydrogen stream is driven fromthe salt cavern 4 by the cavern pressure of the stored hydrogen.Consequently, the return side 3 b of the flow network 3 is designed witha pressure drop not only to limit maximum flow rates and velocity of thestored hydrogen stream, but also, to reduce the pressure of the storedhydrogen stream to pipeline pressure of the hydrogen pipeline 2. It isto be noted, that it is possible to further compress the stored hydrogenstream if required. In this regard, it is possible to conduct anembodiment of the present invention in which the cavern pressure wouldnot be sufficient to return the stored hydrogen stream back to thehydrogen pipeline 2. In such case, a compressor would have to beprovided for such purposes or compressor 14 could be used afterappropriate piping changes.

Control over the minimum volume of hydrogen that is to be maintainedwithin the salt cavern 4 is effectuated by measurement of cavernpressure by pressure transducer 52 and hydrogen temperature bytemperature transducer 54 located within transfer line 26 and the actualhydrogen containing volume of the cavern. Pressure transducer 52 andtemperature transducer 54 are connected to a supervisory control system90 by electrical connections 92 and 94, respectively. Supervisorycontrol system 90 can take many forms that are known in the art and noparticular form of such control for purposes of the present invention ispreferred. For example supervisory control system 90 can incorporate asupervisory control and data acquisition software, that can be obtainedfrom a variety of sources, that is loaded on a dedicated computer thatinterfaces over a local area network with an automated control system,for example a control system incorporating model predictive control orother automated control of less sophistication. The supervisory controland data acquisition system serves to collects data from the controllerspreviously discussed, such as controllers 18, 32, 48, 64 and 70 andpressure and temperature transducers incorporated into such controllers,as well as other pressure and temperature transducers such as 52 and 54,generate alarms and etc. The automated control system 90 in turntransmits targets to the controllers which in the illustrated embodimentare in the main pressure targets to control the control valves. Thelinkages between the controllers 18, 32, 48, 64 and 70 and thesupervisory control system 90 are illustrated by electrical connections96, 98, 100, 102 and 104 respectively. Alternatively or additionally,the supervisory control system 90 could be a human interface to allow anoperator to note pressure and temperature readings and manually transmittargets to the controllers.

The volume computation is accomplished within the supervisory controlsystem 90 by applying to the cavern pressure measured by pressuretransducer 52, a temperature measurement by temperature transducer 54when it measures the stored hydrogen leaving the salt cavern 4 toprovide the basis for calculating the standard volume of gas in thecavern that fills the actual hydrogen volume in the cavern. In lieu ofmeasuring actual temperature, the temperature to be applied could be anadjusted produced gas temperature based on the local geothermalgradient. A conservative approach involves using the higher of the twotemperatures, temperature transducer 54 and the temperature based on thelocal geothermal gradient. In any case, the measurement of the volume ofhydrogen that is derived in a manner set forth above is then compared toa minimum hydrogen volume that must be maintained to maintain thestagnant layer within the salt cavern 4. As a result of such comparison,the removal of stored hydrogen is terminated when the minimum hydrogenvolume is approached. As can be appreciated, this can either be donemanually or automatically by automated controls incorporated intosupervisory control system 90 that would produce targets sent tocontrollers 64 and 70. It is to be pointed out that the pressure, asmeasured by pressure transducer 52, is also used as a constraint that isfed to controller 48. Controller 48 is programmed to respond to suchpressure and shut down compressor 18 when the pressure exceeds themaximum allowable limit that would compromise the structural integrityof the salt cavern 4. As mentioned above, the flow rate of thecompressed hydrogen feed stream could also be stored and used for suchcalculation.

All controllers 18, 32, 48, 64 and 70 could be proportional, integraland differential controllers that are well known in the art and that canbe obtained from a variety of suppliers. Additionally, all of theelectrical connections mentioned above with respect to such control orother controllers mentioned herein can either be hard wired or by radiosignals. As can also be appreciated, although in the illustratedembodiment of the present invention, the flow rates and velocities ofthe compressed hydrogen feed stream and the stored hydrogen stream arelimited by compressor capacity of the hydrogen compressor 14 and bypressure drop in the return side 3 b of flow network 3, the controllers32 and 72 could also be programmed with constraints that would act as analternative means of limiting flow rates and velocities.

With additional reference to FIG. 2, salt cavern 4 is formed by solutionmining in which water capable of dissolving salt is injected through apipe 110 known as a brine string. The water dissolves the salt and theresulting brine, during the mining operation, is returned through theannular space 29 formed in the final well casing 28 between the innerwall of the final well casing and the pipe 110. As known in the art, theinjection of the water and removal of the brine could be alternated sothat the water is injected through the annular space 29 formed in thewell casing 28 and removed through the pipe 110. After the miningoperation is complete, the residual brine in the cavern is removedthrough pipe 110 by pressure displacement resulting from injection ofhydrogen through the final casing 28. Once the brine level reaches thebottom of pipe 110, the pipe is sealed off by a valve 112 which can beseen in FIG. 1. Although not illustrated, but as would be known in theart, the final well casing 28 is cemented in place and penetratesoverlying formations known as cap rock. The resulting salt cavern 4 hasa residual brine layer 114 also known as a brine sump located in thebottom of the salt cavern 4. The sides of the salt cavern 4 can be saidto be defined by a side regions 116. The top and bottom of the saltcavern are defined by a top or roof by a top region 118 and a bottomregion 120, respectively.

As has been discussed above, it has been found that the salt cavern 4can be operated to obviate any need to remove carbon dioxide andtherefore, the carbon dioxide content of the hydrogen feed can be veryclose to that of the stored hydrogen stream reinjected back into thehydrogen pipeline 2. For example, the increase in carbon dioxide contentof the stored hydrogen stream over the feed stream of hydrogen 10 can beno greater than 1.5 ppmv and preferably, less than 0.5 ppmv. Themaintenance of at least a minimum volume of stored hydrogen at alltimes, namely before, during and between times at which the compressedhydrogen feed stream is injected into the salt cavern 4 and the storedhydrogen stream is withdrawn from the salt cavern 4 produces a stagnantlayer of hydrogen that is also maintained in the salt cavern 4.Preferably, the minimum volume of stored hydrogen that is stored withinthe salt cavern 4 is maintained at a volume ratio equal to a storedvolume of the hydrogen to the actual cavern volume of no less than 29scf/cf for such purposes. As discussed above, this maintenance of theminimum volume of hydrogen within the salt cavern 4 is provided bypressure and temperature measurements by pressure and temperaturetransducers 52 and 54 and the actual volume of contained hydrogen in thecavern. As illustrated, the stagnant layer of hydrogen has a bottomportion 122 overlying the residual brine layer 114, a lateral portion124 situated at the side regions 116 of the salt cavern and a topportion 126 situated at the top or roof region 118 of the salt cavern 4.

As mentioned above, the stagnant layer has a carbon dioxideconcentration that is a potential source of contamination to the storedhydrogen stream to be injected back to the hydrogen pipeline 2. Thecarbon dioxide that is present within the stagnant layer, ascontamination to the stored hydrogen stream to be returned to thehydrogen pipeline 2, arises principally from the residual brine layer114. The carbon dioxide present within the residual brine layer 114enters the salt cavern 4 from the solution mining water used in formingthe salt cavern 4 as well from carbon dioxide, carbonate and bicarbonatecontaminants that may have been contained in the dissolved salt and suchcarbon dioxide remains in the residual brine layer 114. It is alsopossible that some carbon dioxide can be present within the lateral andtop portions 124 and 126 from the cavern wall. However, so long as thestagnant layer is not disturbed during the injection and withdrawal ofhydrogen into and from the salt cavern 4, such carbon dioxidecontamination of an interior region 130 of the salt cavern 4 thatboarders the stagnant layer will be inhibited and as a result, carbondioxide contamination of the stored hydrogen stream from the carbondioxide content of the stagnant layer will also be inhibited. The term“inhibited” as used here and in the claims means that any transport ofthe carbon dioxide contamination from the stagnant layer to the interiorregion 130 is limited to such contamination arising from the moleculardiffusion of the carbon dioxide from the stagnant layer to the interiorregion 130 of the salt cavern 4. Such molecular diffusion of carbondioxide is an extremely slow process. In this regard, it has beencalculated that if the stagnant layer were produced as described aboveand the same were left undisturbed, it would take more than 1000 daysfor the carbon dioxide contamination to diffuse into the interior region130 to a concentration that is 10% of the concentration of carbondioxide at the hydrogen brine interface when measured at a level 100feet above the brine layer 114.

The final well casing 28 is positioned within the salt cavern 4 so thata lower end 128 of the final well casing 28 is situated beneath the topregion 118 of the salt cavern 4 to allow the formation of the topportion 126 of the stagnant layer that would be left undisturbed byinjection and withdrawal of the hydrogen from the salt cavern. It ispossible to practice the present invention with the lower end 128 of thefinal well casing 28 level or nearly level with the top region 118 ofthe salt cavern 4. If this were done, then the stagnant layer would nothave a top portion 126 that was maintained at all times and potentially,carbon dioxide contamination from the top region 118 of the salt cavern4 to the interior region 130 of the salt cavern could occur, but carbondioxide contamination from this region will impact the stored hydrogento a lesser extent than could result from the bottom region 122 of thestagnant layer.

With respect to the placement of the final well casing 28 or otherconduit having a lower open end that does not include a diffuser 136 tobe discussed, the lower end 128 of the final well casing 28 should bespaced a lower vertical distance “LO” from the surface of the brinelayer 114 that is preferably no less than 250 feet and at a lateraldistance “LA” from the side region 116 of the salt cavern 4 of no lessthan 40 feet as measured from a vertical line extending between 10 and250 feet below the lower end 128 of the final well casing 28 shown inthe drawing as “MD”. Additionally, if a top portion 126 is to bemaintained, then the lower end 128 should be spaced an upper verticaldistance “U” of no less than 50 feet.

The limitation of the flow rate and velocity of the compressed hydrogenfeed stream will result in the momentum of the compressed hydrogen feedstream dissipating before reaching the stagnant layer, namely portions122 and 124 thereof and top portion 126 if present. The limitation onthe flow rate and velocity at which the stored hydrogen stream iswithdrawn from the salt cavern will ensure that gas velocities are notproduced in the stored hydrogen, adjacent the lateral and bottomportions 124 and 122 of the stagnant layer and also, the top portion 126thereof if the same is present. Preferably, the flow rate of thecompressed hydrogen feed stream is limited such that an injection ratioexists that is equal to the injection flow rate divided by the actualcavern volume of salt cavern 4 that is no greater than 7.5 scfd/cf ofcavern volume. The injection velocity of the compressed hydrogen feedstream, as measured at the lower end 128 of the final well casing 28 orother conduit used for such purpose, is preferably no greater than 100feet per second. The flow rate of the stored hydrogen stream can belimited such that a withdrawal ratio of the withdrawal flow rate to theactual cavern volume is no greater than 10.0 scfd/cf. The withdrawalvelocity of the stored hydrogen stream, as measured at the lower end 128of the final well casing or other conduit should preferably be nogreater than 150 feet per second. As can be appreciated, such flow ratesand velocities are calculated values that will work with the distances“LO”, “LA” and “U” discussed above to inhibit carbon dioxidecontamination of the stored hydrogen stream. Obviously such flow ratesand velocities could change depending upon the placement of final wellcasing 28 within the salt cavern 4. For example, the closer the lowerend 128 of the final well casing 28 or other conduit to the residualbrine layer 114, the lower the limiting flow rates and velocities of thecompressed hydrogen feed stream and the stored hydrogen stream. In thisregard, the minimum volume of hydrogen that would have to be maintainedwithin the salt cavern and the flow rates and velocities could becomputed by one skilled in the art by modeling the operation of the saltcavern under consideration by computational fluid dynamics software suchas ANSYS CFX software obtained from Ansys, Inc., Southpointe, 275Technology Drive, Canonsburg, Pa. 15317, USA. This modeling woulddisclose the flow patterns within the salt cavern during injection andwithdrawal of the hydrogen at various flow rates, velocities, placementof the final well casings and cavern pressures. Regions of the saltcavern in which no flow patterns occur define the stagnant layer.

When the present invention is practiced in the manner set forth above,namely, with the positioning of the lower end 128 of the final wellcasing 28 and the limitation on flow rates and velocities, where thehydrogen flowing within the hydrogen pipeline 2 contains less than 1.0ppmv carbon dioxide and less than 8 ppmv carbon monoxide, the storedhydrogen stream will be within a typical hydrogen pipeline specificationin which a sum of a carbon dioxide content and carbon monoxide contentis less than 10 ppmv. However, under a more stringent specification,where the hydrogen flowing within the pipeline will contain less than0.1 ppmv carbon dioxide and less than 0.6 ppmv carbon monoxide, thestored hydrogen stream will contain a carbon dioxide content and carbonmonoxide content that when added together is less than 1.0 ppmv. Thisbeing said the present invention has applicability to other pipelinespecifications having higher total carbon dioxide and carbon monoxideconcentrations.

Although in the prior art, minimum volumes of hydrogen have beenmaintained within salt cavern that would likely have within thenumerical limits set forth above and injection and withdrawal flow ratesand velocities have also been used that are likely to have been withinthe numerical limits set forth above, it has not been appreciated in theprior art that the specific maintenance of such numerical values lead tothe formation of a stagnant layer and the prevention of the disturbanceof such stagnant layer so that carbon dioxide removal is not required.In fact, carbon dioxide removal was believed to be necessary even when asalt cavern was operated within such limitations.

With additional reference to FIG. 3, multiple, dedicated conduits can beused for the injection of the compressed hydrogen feed stream andwithdrawal of the stored hydrogen stream from the salt cavern 4. Exceptas noted below, the operation of the system to be used in connectionwith such conduits is the same as that described with reference to FIGS.1 and 2 above.

The multiple, dedicated conduits include an injection conduit 132 thatis situated within an additional final well casing 134. The lower end ofinjection conduit 132 is provided with a flow diffuser 136. Injectionconduit 132 is formed by a pipe that is inserted within the final wellcasing 134 that is also set in concrete in the same manner as final wellcasing 28. The injection conduit 132 is inserted into the final wellcasing 134 and a transfer conduit 138 communicates between the valve 24,the operation of which was previously described, and a valve 140 that isleft in a normally open position. When hydrogen is to be stored in saltcavern 4, valve 24 is set in an open position and valve 56 is set in aclosed position and the compressed hydrogen feed stream is supplied fromthe compressor 14 to the salt cavern 4 through the transfer conduit 138.As illustrated, transfer conduits 138 and 154 are instrumented with thepressure transducers 52 and 53 and a temperature transducers 54 and 55that function in the manner also discussed above. The pressure andtemperature transducers 53 and 55 function to calculate the actual flowrate of the stored hydrogen stream and although not illustrated, wouldbe connected by suitable electrical connections to the supervisorycontroller 90. A well head casing valve 142 associated with final wellcasing 134 is set in a closed position. Unlike the embodiments shown anddescribed in FIGS. 1 and 2, the stored hydrogen stream does not flowthrough injection conduit 132, but rather, from a withdrawal conduitthat is formed from a final well casing 146 that is used in connectionwith mining the salt cavern 4 and as such, has a brine string 148 leftin place that is sealed by a valve 150. In this regard, final wellcasing 146 and brine string 148 are identical to final well casing 28and brine string 110, previously described. When stored hydrogen is tobe supplied back to the hydrogen pipeline 2, valve 24 in a closedposition and valve 56 is set in an open position and the stored hydrogenstream flows through a wellhead casing valve 152 to a transfer conduit154 that is connected to valve 56.

As can be appreciated, the use of dedicated conduits involves theformation of an additional well and etc. However, the provision of thediffuser 136 within the injection conduit has the advantage of lesseningany possible disturbance of the bottom portion 122 of the stagnant layeroverlying the brine layer 114. In this regard, diffuser 136 is formed bya sleeve 156 that is welded to injection conduit 132 and is closed atits bottom by a plate 158 welded to the sleeve 156. A series ofperipheral openings 160 are provided from which the compressed hydrogenfeed stream flows into the salt cavern 4. As such, hydrogen is preventedfrom being expelled directly toward the residual brine layer 114. It isto be noted, however, that in place of the diffuser 136, other designsare possible, for example, more sophisticated devices such as screens orspecially designed devices to redirect the linear momentum of thecompressed hydrogen feed stream being injected through the injectionconduit 132.

The lower end of the injection conduit 132 that is formed by thediffuser 136 should preferably situated no less than 200 feet above theresidual brine layer 114 of the salt cavern 4. The reason for suchdecrease over an open ended conduit such as has been discussed above isthat the incoming hydrogen stream is not directed directly at theresidual brine layer 114. The preferred limits for the residual hydrogenthat is maintained in salt cavern 4, the injection and withdrawal flowrates and velocities are all the same as have been discussed above withrespect to FIGS. 1 and 2 except that the velocities are computed on thebasis of a different flow area and the injection velocity of thecompressed hydrogen feed stream is less than that of the open endedconduit provided by final well casing 28. With respect to diffuser 136,the flow area that would be used in connection with computing thevelocity would be the area provided by the peripheral openings 160. Thevelocity of the compressed hydrogen stream, as measured at suchperipheral openings 160, should be less than 50 feet per second.However, it is to be noted that actual velocity and placementlimitations will depend on the design of the particular flow diffuserused.

Although in the embodiment discussed above, dedicated injection andwithdrawal conduits are utilized for injecting and withdrawing hydrogen,embodiments of the present invention are also possible in which theinjection conduit 132 and the flow diffuser 136 are used in connectionwith withdrawing hydrogen in the same manner as well casing 28 describedabove in connection with FIGS. 1 and 2. Also possible, as has beendiscussed above, is to have multiple conduits that are in the form offinal well casings 146 or 28 that are either used without a diffuser inparallel or in a dedicated fashion in which one of such conduits isconnected to valve 24 for injection of the compressed hydrogen feedstream into the salt cavern 4 and another is connected to valve 56 forthe withdrawal of hydrogen from the salt cavern 4. It is also possibleto have two pipes such as injection conduit 132 within a single finalwell casing. This being said, the use of final well casing 28 is used asa conduit for withdrawal and injection of the hydrogen from and to,respectively, salt cavern 4 is convenient because such conduit is inplace after the solution mining of the salt cavern 4.

While the present invention has been described with reference topreferred embodiments, as would occur to those skilled in the art,numerous changes, additions and omission can be made without departingfrom the spirit and scope of the invention as set forth in the appendedclaims.

I claim:
 1. A method of storing and supplying hydrogen to a hydrogenpipeline comprising: compressing a feed stream of the hydrogen toproduce a compressed hydrogen feed stream; injecting the compressedhydrogen feed stream into a salt cavern to produce stored hydrogenwithin the salt cavern through at least one conduit and withdrawing astored hydrogen stream, composed of the stored hydrogen, from the saltcavern through the at least one conduit, the salt cavern having aresidual brine layer located at a bottom region of the salt cavern andside regions extending upwardly from the bottom region of the saltcavern and the at least one conduit having at least one lower endlocated in an interior region of the salt cavern and spaced above thebrine layer and from the side regions of the salt cavern; introducingthe stored hydrogen stream after having been withdrawn from the saltcavern into the pipeline without removing carbon dioxide present withinthe stored hydrogen stream; maintaining at least a minimum quantity ofthe stored hydrogen within the salt cavern before, during, and betweentimes at which the compressed hydrogen feed stream is injected and atwhich the stored hydrogen stream is withdrawn such that a stagnant layerof hydrogen is maintained that borders the interior region and has atleast a bottom portion overlying the residual brine layer and a lateralportion situated along the side regions of the salt cavern, the stagnantlayer having a carbon dioxide content that is a potential source ofcarbon dioxide contamination to the stored hydrogen stream; and limitingthe flow rates and the velocities at which the compressed hydrogen feedstream is injected into the salt cavern and the stored hydrogen streamis withdrawn from the salt cavern such that the stagnant layer is notdisturbed and the carbon dioxide contamination of the stored hydrogenstream from the stagnant layer is inhibited.
 2. The method of claim 1,wherein: the at least one lower end of the at least one conduit isspaced below a top region of the salt cavern, located opposite to thebottom region of the salt cavern; and the stagnant layer also has a topportion extending along the top region of the salt cavern and situatedopposite to the bottom portion of the stagnant layer.
 3. The method ofclaim 1 wherein water is removed from the stored hydrogen stream priorto injection into the pipeline.
 4. The method of claim 1, wherein: thehydrogen feed stream is compressed to a pressure above the pipelinepressure within the pipeline; the stored hydrogen has a cavern pressurethat is above the pipeline pressure; the stored hydrogen stream isremoved from the salt cavern as a consequence of the cavern pressure;and the stored hydrogen stream is reduced to the pipeline pressure priorto injecting the stored hydrogen stream into the pipeline.
 5. The methodof claim 1, wherein the at least one conduit has an injection conduitand a withdrawal conduit and the compressed hydrogen feed stream isinjected into the salt cavern through the injection conduit and thestored hydrogen stream is withdrawn from the salt cavern through thewithdrawal conduit.
 6. The method of claim 1, wherein the at least oneconduit comprises an injection conduit having a flow diffuser from whichat least the compressed hydrogen feed stream is injected into the saltcavern.
 7. The method of claim 1, wherein: the minimum volume of thehydrogen stored within the salt cavern is maintained at a volume ratioequal to a stored volume of the hydrogen to the actual cavern volume ofno less than 29.0 scf/cf; the at least one lower end of the at least oneconduit is open; the at least one lower end of the at least one conduitis spaced from the residual brine layer at a lower vertical distance ofno less than 250 feet; the at least one lower end of the at least oneconduit is spaced from the side regions of the salt cavern at a lateraldistance of no less than 40 feet from a vertical line extending between10 and 250 feet below the at least one lower end of the at least oneconduit; and the flow rates and velocities are limited such that, asmeasured at the at least one lower end of the at least one conduit, thecompressed hydrogen feed stream is injected at an injection ratio equalto an injection flow rate of the compressed hydrogen feed stream to theactual cavern volume of no greater than 7.5 scfd/cf and at an injectionvelocity of the compressed hydrogen feed stream of no greater than 100feet per second and the stored hydrogen stream is withdrawn at awithdrawal ratio equal to the withdrawal flow rate of the storedhydrogen stream to the actual cavern volume of no greater than 10.0scfd/cf and at a withdrawal velocity of the stored hydrogen stream of nogreater than 150 feet per second.
 8. The method of claim 7, wherein: theat least one lower end of the at least one conduit is spaced below a topregion of the salt cavern, located opposite to the bottom region of thesalt cavern; and the stagnant layer also has a top portion extendingalong the top region of the salt cavern and situated opposite to thebottom portion of the stagnant layer; and the at least one lower end ofthe at least one conduit is spaced from the top region of the saltcavern at an upper vertical distance of no less than 50 feet.
 9. Themethod of claim 7 or claim 8, wherein the hydrogen feed stream containsless than 1.0 ppmv carbon dioxide and less than 8 ppmv carbon monoxideand a sum of a carbon dioxide content and carbon monoxide content in thestored hydrogen stream is less than 10 ppmv.
 10. The method of claim 7or claim 8, wherein hydrogen feed stream contains less than 0.1 ppmvcarbon dioxide and less than 0.6 ppmv carbon monoxide and a sum of acarbon dioxide content and carbon monoxide content in the storedhydrogen stream is less than 1.0 ppmv.